Method for Reducing Aqueous Content of Oil-Based Fluids

ABSTRACT

A method for reducing the aqueous content of oil-based drilling fluid includes contacting an invert emulsion wellbore fluid with a water absorbing polymer, interacting the water absorbing polymer with the wellbore fluid for a sufficient period of time so that the water absorbing polymer absorbs at least a portion of the aqueous fluid form the wellbore fluid; and separating the water absorbing polymer containing the absorbed water from the wellbore fluid.

FIELD OF INVENTION

The invention relates generally to wellbore fluids, and morespecifically to the removal of the aqueous content from the oil-basedwellbore fluids.

BACKGROUND OF INVENTION

When drilling or completing wells in earth formations, various fluidstypically are used in the well for a variety of reasons. Common uses forwell fluids include: lubrication and cooling of drill bit cuttingsurfaces while drilling generally or drilling-in (i.e., drilling in atargeted petroliferous formation), transportation of “cuttings” (piecesof formation dislodged by the cutting action of the teeth on a drillbit) to the surface, controlling formation fluid pressure to preventblowouts, maintaining well stability, suspending solids in the well,minimizing fluid loss into and stabilizing the formation through whichthe well is being drilled, fracturing the formation in the vicinity ofthe well, displacing the fluid within the well with another fluid,cleaning the well, testing the well, fluid used for emplacing a packer,abandoning the well or preparing the well for abandonment, and otherwisetreating the well or the formation.

Drilling fluids or muds typically include a base fluid (water, diesel ormineral oil, or a synthetic compound), weighting agents (most frequentlybarium sulfate or barite is used), emulsifiers and emulsifier systems,fluid loss additives, viscosity regulators and the like, for stabilizingthe system as a whole and for establishing the desired performanceproperties.

Oil-based drilling fluids are generally used in the form of invertemulsion muds. Invert emulsion fluids are employed in drilling processesfor the development of oil or gas sources, as well as, in geothermaldrilling, water drilling, geoscientific drilling, and mine drilling.Specifically, the invert emulsion fluids are conventionally utilized forsuch purposes as providing stability to the drilled hole, forming a thinfilter cake, lubricating the drilling bore and the downhole area andassembly, and penetrating salt beds without sloughing or enlargement ofthe drilled hole.

An invert emulsion mud consists of three phases: an oleaginous phase, anaqueous phase, and a finely divided particle phase. The discontinuousaqueous phase is dispersed in an external or continuous oleaginous phasewith the aid of one or more emulsifiers. The oleaginous phase may be amineral or synthetic oil, diesel or crude oil, while the aqueous phaseis usually calcium chloride, sodium chloride or other brine.

The dispersed aqueous phase has several functions. The aqueous phasereplaces part of the oleaginous phase, thereby building volume andreducing the total fluid cost. Further, the aqueous phase contributes tofluid density through its higher specific gravity. The highly dispersedstate of the aqueous phase contributes to rheology and to fluid losscontrol. The dispersed aqueous phase also helps improve the inhibitionof water-reactive shales by creating a favorable salinity balance.

The volume ratio of the oleaginous phase to the aqueous phase isreferred to as the oil/water ratio (OWR). The OWR is commonly quoted asproportions out of a total of one hundred units, e.g. 90/10, 75/25, etc.Occasionally, through contamination at surface or influx of formationwaters downhole, the water cut of an oil-based fluid increases, therebydecreasing the OWR. Such a decrease in the OWR can have an adverseeffect on the rheology, density, and emulsion stability of the fluid.There are also occasions where an existing fluid, designed originally tohave a higher water content, may have to be used in a drilling operationthat requires a lower water portion. In both such cases, the water cutof the fluid has to be reduced in order to bring back the fluidproperties within specification. In other words, the OWR has to beincreased.

Previous attempts in the prior art to increase OWR has included dilutionwith the oleaginous phase, i.e. adding more oil to the oil-baseddrilling fluid. However, as more oil is added to the drilling fluid, theamount of fluid additives, such as rheology and fluid loss additives andweight material, necessarily increases in order to maintain the variousdesirable fluid properties. Consequently, not only does dilution of theoleaginous phase increase the overall volume of the drilling fluid, butit also increases costs, inventory, and waste.

Previous attempts in the prior art have also used a desiccant to removesmall portions of water from a drilling fluid. This has been useful inapplications requiring the drilling fluid remain in a water-free state.While these attempts have been successful at removing small quantitiesof water, these attempts have not addressed the need to remove largeamounts of water from the drilling fluid during drilling, or adjustingan existing fluid to meet the requirements for a particular application.Further, these attempts do not address the need of removing aqueouscontent from an invert emulsion oil-based drilling fluid.

Accordingly, there exists a need for means to economically increase theOWR while reducing the amount of contaminant water present in the fluidwithout altering the fluid's desired properties. Further, there exists aneed to remove large amounts of non-emulsified water from an oil-baseddrilling fluid. Further yet, there exists a need to remove theemulsified aqueous content from an invert emulsion oil-based drillingfluid.

SUMMARY OF INVENTION

In one aspect, the present invention relates to a method for removingthe aqueous content from a wellbore fluid. The method may include thesteps of contacting a wellbore fluid with a water absorbing polymer,where the wellbore fluid includes an invert emulsion, allowing the waterabsorbing polymer to interact with the wellbore fluid for a sufficientperiod of time so that the water absorbing polymer absorbs at least aportion of the aqueous content, and separating the water absorbingpolymer containing the absorbed water from the wellbore fluid.

In another aspect, the present invention relates to a method forremoving the non-emulsified aqueous content from an invert emulsionwellbore fluid in situ. The method may include the steps of determininga design limit of the oil-to-water ratio for the wellbore fluid, feedingthe wellbore fluid to the borehole, monitoring the oil-to-water ratio ofthe wellbore fluid, adding a water absorbing polymer when theoil-to-water ratio decreases below the design limit, allowing the waterabsorbing polymer to interact with the wellbore fluid for a sufficientperiod of time so that the water absorbing polymer absorbs sufficientaqueous content to return the oil-to-water ratio above the design limit,and separating the water absorbing polymer containing the absorbed waterfrom the wellbore fluid.

In another aspect, the present invention relates to a method forremoving the emulsified aqueous content from a wellbore fluid. Themethod may include the steps of determining a desired oil-to-water ratiofor the existing invert emulsion wellbore fluid, adding a sufficientamount of water absorbing polymer to the existing wellbore fluid toadjust the existing oil-to-water ratio to the desired oil-to-waterratio, allowing the water absorbing polymer to interact with theexisting wellbore fluid for a sufficient period of time so that thewater absorbing polymer absorbs sufficient aqueous content to adjust theexisting wellbore fluid to the desired oil-to-water ratio, therebyyielding an adjusted wellbore fluid, and separating the water absorbingpolymer containing the absorbed aqueous content from the adjustedwellbore fluid.

Other aspects and advantages of the claimed subject matter will beapparent from the following description and the appended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows a graphical representation of the absorption of fresh waterover a period of time.

FIG. 2 shows a graphical representation of the absorption of sea waterover a period of time.

FIG. 3 shows a graphical representation of the effect of temperature onsea water absorption over a period of time.

FIG. 4 shows a graphical representation of the absorption of sea waterin an oil environment over a period of time.

FIG. 5 shows a graphical representation of the absorption of sea waterin an oil environment containing an invert emulsifier over a period oftime.

FIG. 6 shows a graphical representation of the absorption of sea waterin an oil environment containing an invert emulsifier and barite over aperiod of time.

FIG. 7 shows a graphical representation of the absorption of emulsifiedfresh water over a period of time.

FIG. 8 shows a graphical representation of the absorption of emulsifiedbrine over a period of time.

FIG. 9 shows a graphical representation of the absorption ofnon-emulsified brine, setting the percent concentration (w/w) againstthe water activity.

FIG. 10 shows a flow chart for removing aqueous content from an invertemulsion drilling fluid using a water absorbing polymer.

FIG. 11 shows a flow chart for removing the non-emulsified aqueouscontent from an invert emulsion drilling fluid when the fluid is inprocess.

FIG. 12 shows a flow chart for removing emulsified aqueous content froman invert emulsion drilling fluid using a water absorbing polymer.

DETAILED DESCRIPTION

In one aspect, embodiments of the invention are generally directed to amethod for removing aqueous content from an oil based drilling fluid,thereby increasing the OWR. As described above, during the use of awellbore fluid, water often contaminates the wellbore fluid so as toincrease the total volume of the wellbore fluid and alter the OWR, aswell as the concentration of salts or other wellbore additives fromtheir initial, desired concentration. According to the embodiments ofthe present invention, excess aqueous content may be removed from awellbore fluid by contacting the wellbore fluid with a water absorbingpolymer. Wellbore fluids that may be used with a water absorbing polymerin accordance with the present invention may include any invert emulsionfluids having excess water that have been collected form a wellbore,such as drilling fluids, completion fluids, workover fluids, anddrill-in fluids.

In one embodiment of the invention, a method 100 of removing at least aportion of the aqueous content from a wellbore fluid is depicted in FIG.10. The wellbore fluid comprises an invert emulsion oil-based drillingfluid. As stated above, an invert emulsion consists of three phases: anoleaginous phase, an aqueous phase, and a finely divided particle phase.In the invert emulsion oil-based drilling fluid, the discontinuousaqueous phase is dispersed in an external or continuous oleaginous phasewith the aid of one or more emulsifiers.

The oleaginous continuous phase is preferably selected from at least oneof the following: mineral oil, synthetic oil, diesel, crude oil, andmixtures thereof. The aqueous discontinuous phase is preferably selectedfrom at least one of the following: fresh water, sea water, brine,mixture of water and water soluble organic compounds, and mixturesthereof. As used herein, brine refers to various salts and salt mixturesdissolved in an aqueous solution. A brine of the present invention mayinclude monovalent or/and divalent salts of inorganic or organic acids.Preferably, a brine of the present invention includes calcium, sodium orpotassium chloride; calcium, sodium or potassium bromide, potassium orcesium formate dissolved in an aqueous solution.

Method 100 comprises a contacting step 110, where a water absorbingpolymer is contacted with the wellbore fluid. The water absorbingpolymer is preferably a water absorbing crystalline polymer capable ofabsorbing at least 10 times its own weight in fresh water. Particularly,the water absorbing polymer may include acrylamide based polymers andcopolymers, starch derivatives, and combinations thereof, as well asother water absorbing polymers known in the art.

The absorbance capacity of the water absorbing polymers may be explainedby the matix-like structure of dry water absorbing polymer particle. Thedry polymer may contain charged species within the matrix, such that theionization of the polymer will cause the matrix network to open andcreate cavities that may absorb water by capillary action. Waterabsorbed into the polymer may be retained by hydrogen bonds that formbetween the charged species and the water. The actual mechanism forwater absorbance and retention may vary based on the structure of aparticular water absorbing polymer. For example, polyacrylamide, in thedry powdered state, contains a coiled backbone, lined with amide groups.When exposed to an aqueous solution, the amide groups dissociate intonegatively charged amide ions, which may repel one another along thepolymer chain. The repelling amide ions thereby widen the polymer coilsand allow water to move into contact with inner amide groups, furthercontinuing the widening or welling of the polymer. Water is retainedwithin the polymer due to hydrogen bonding between the water and theamide ions on the polymer. Because of the crosslinking that exists inthese water absorbing polymers, the water absorbing polymers remaininsoluble in an aqueous solution.

Method 100 further comprises an interacting step 120, where the waterabsorbing polymer is allowed to contact the wellbore fluid for a periodof time. The period of time should be sufficient so that the waterabsorbing polymer absorbs at least a portion of the aqueous fluid fromthe invert emulsion. The amount of time will vary depending on theapplication, and can be easily ascertained through representativetesting. However, equilibrium has been obtained between 1 and threehours, depending on salinity as well as the state of emulsification.

Method 100 further comprises a separating step 130, where the waterabsorbing polymer containing the absorbed water from the wellbore fluidis separated from the wellbore fluid. This can be achieved throughvarious filtration techniques, including passing the invert emulsionwellbore fluid containing the water absorbing polymer over appropriatesized shaker screens to remove the swollen water absorbing polymer.Alternatively, centrifuges or hydrocylcones, which work on the basis ofsize and density differences, may also be used to effectuate separationof the water absorbing polymer from the wellbore fluid.

In another aspect, embodiments of the invention are generally directedto a method for adjusting the OWR of the invert emulsion wellbore fluid.This may become necessary to remove excess downhole influx of water, oradjust the OWR of an existing wellbore fluid so it may meet thespecifications of a particular application.

In one embodiment of the invention, a method 200 for removing thenon-emulsified aqueous content during the drilling process is depictedin FIG. 11. It may become necessary to remove excess aqueous contentthroughout the drilling process if, for example, there is an influx ofwater into the wellbore or there is surface contamination of thewellbore fluid. If the water portion of the invert emulsion wellborefluid increases, the water absorbing polymer can be added to absorb atleast a portion of the aqueous content, thereby increasing the OWR. Thewater absorbing polymer will absorb the influx water first, and thenabsorb the discontinuous aqueous phase of the wellbore fluid.

Method 200 comprises a determining step 210, where the design limit ofthe OWR for the invert emulsion wellbore fluid is determined. The designlimit is the minimum OWR the wellbore fluid will tolerate withoutadversely effecting the rheology, density, and emulsion stability of thewellbore fluid. Accordingly, the design limit will vary depending uponthe particular application.

Method 200 further comprises a feeding step 220, where an invertemulsion wellbore fluid is fed to the borehole. The wellbore fluid isgenerally fed to a borehole via nozzles in a drill bit, or other methodsalready known in the art.

Method 200 further comprises a monitoring step 230, where the OWR of thewellbore fluid is monitored. Determination of the OWR can be done bydistilling the liquid part of the drilling fluid in a device calledretort, or other means known in the art. The ideal OWR will varydepending upon the particular application, as will the design limit ofthe wellbore fluid. If the determined OWR falls below the design limitOWR, removal of the excess aqueous content becomes necessary.

Method 200 further comprises a contacting step 240, where the invertemulsion drilling fluid is contacted with a water absorbing polymerthrough introducing the water absorbing polymer to the circulatingdrilling fluid in the wellbore. The water absorbing polymer can be addeddirectly to the active pit, or the water absorbing polymer may be addedin the flow line carrying the invert emulsion wellbore fluid.

Method 200 further comprises an interacting step 250, where the waterabsorbing polymer interacts with the invert emulsion drilling fluid fora sufficient period of time so that the water absorbing polymer absorbssufficient aqueous content to return the OWR above the design limit. Inone embodiment, sub-millimetric polymer granules are added to thewellbore fluid and allowed to continuously circulate within thewellbore. As the polymer granules circulate with the wellbore fluid, atleast a portion of the aqueous content of the wellbore fluid will beabsorbed by the polymer granules. As the polymer granules absorb theaqueous content, the polymer granules will begin to expand.

The size of the water absorbing polymer is important, as it affects therate of absorption. The smaller the size of the water absorbing polymergranules, the larger the surface area of the particles, yielding ahigher absorption rate. However, the granules should not be so smallthat they negatively impact the rheology of the drilling fluid. Therheology of the drilling fluid may become negatively impacted if theparticle size of the polymer granules become comparable to that of thedrilling fluid solid constituents, i.e. the weight material and thefluid loss additive. Additionally, the granules should not be so smallin size that they will pass through the shaker screens before they haveswollen. Consequently, the particle size of the polymer granules is atleast 300 micron.

Method 200 further comprises a separating step 260, where the waterabsorbing polymer containing the absorbed aqueous content is separatedfrom the invert emulsion drilling fluid. After the water absorbingpolymer has been allowed to contact the invert emulsion drilling fluidlong enough for at least a portion of the aqueous content to be absorbedby the water absorbing polymer, the water absorbing polymer may removedfrom the invert emulsion drilling fluid. This may be done by passing thefluid through suitable sized shaker screens. Filtration of the aqueouscontent-bearing water absorbing polymer can be achieved after the waterabsorbing polymer has swelled enough to be caught by the shaker screens.However, if the water absorbing polymer has not swollen sufficiently,the water absorbing polymer will pass through the shaker screen andcontinue to circulate through the wellbore. This allows for continualaqueous content removal until all the water absorbing polymer swellsenough to be removed by the shaker screens.

In another embodiment of the present invention, a method 300 forremoving a portion of the emulsified aqueous content of an existinginvert emulsion wellbore fluid is depicted in FIG. 12. The existing OWRof an existing invert emulsion wellbore fluid can be determined byretort, as stated above. In certain circumstances, the existing OWR ofan invert emulsion wellbore fluid may need to be increased so that theinvert emulsion wellbore fluid meets specifications of a particularapplication. Consequently, it would be necessary to remove part of thediscontinuous aqueous phase of the invert emulsion wellbore fluid.

Method 300 comprises a determination step 310, where the desired OWR isdetermined. The desired OWR will vary depending upon a givenapplication. Factors considered when determining the desired OWR includethe fluid density, rheology, fluid loss properties and costs.

Method 300 further comprises an addition step 320, where a sufficientamount of the water absorbing polymer is added to the existing wellborefluid to adjust the existing OWR to a desired OWR. In one embodiment,the existing wellbore fluid is held in storage, and polymer granules areadded to the existing wellbore fluid. As previously stated, the size ofthe polymer granules affects the rate of absorption. Because theexisting wellbore fluid is held in storage, and is not actively involvedin drilling a wellbore, the amount of time it takes to adjust the OWR tothe desired OWR is not as critical. Consequently, larger polymergranules are preferred. While larger granules may be used, they shouldnot be so large as to be prematurely filtered during separating step340. Therefore, polymer granules between 0.3 and 1.0 millimeter are mostpreferred

Method 300 further comprises an interacting step 330, where the invertemulsion wellbore fluid interacts with the water absorbing polymer for asufficient period of time for the water absorbing polymer to absorbsufficient aqueous content to adjust the existing OWR to the desiredOWR. In one embodiment, the invert emulsion wellbore fluid is moderatelyagitated for the duration of the time period. The agitation should be ofan adequate level to distribute the polymer granules uniformlythroughout the drilling fluid, i.e. prevent separation due to densitydifference.

Method 300 further comprises a separating step 340, where the waterabsorbing polymer containing the absorbed aqueous content is separatedfrom the invert emulsion wellbore fluid. Once the desired OWR isreached, separation may be done by passing the invert emulsion wellborefluid through suitable sized shaker screens.

EXAMPLES

The following examples demonstrate the capability of water-swellingpolymers to remove water or salt solution from an aqueous andnon-aqueous liquid environment. Granules of an acrylamide copolymer(POLYSWELLS®, M-I SWACO) were used in all the examples given below. Thegranules were roughly cubic in shape, with approximate size 2-4 mm.These were ground in a small laboratory grinder to a d₉₀ of about 400micron. Unless otherwise stated, all the tests were carried out inambient temperature (20-25° C.).

Examples 1-3 are general demonstrations of water absorption capacity ofthe polymer. Examples 4-6 generally show the high capacity of thepolymer for removing non-emulsified water from a non-aqueous environmentsuch as an oil-based fluid. This is analogous to surface contaminationor down hole influx of water. Examples 7-9 generally illustrate theability of the polymer, dispersed in an oil phase, to extract water froman emulsified aqueous phase. This is analogous to treating an existingoil-based fluid in order to increase its OWR.

Example 1

One gram of the polymer was added to a 250 mL beaker containing freshwater and stirred gently. The polymer granules were removed by sievingand weighed at intervals, then returned to the beaker. FIG. 1 shows theweight gain of the polymer against time of interaction between thepolymer and the fresh water. The results show that the polymer absorbsmore than one hundred (100) times its own weight of fresh water in twohours.

Example 2

One gram of the polymer was added to a 250 mL beaker containing seawater and stirred gently. The polymer granules were removed by sievingand weighed at intervals, then returned to the beaker. FIG. 2 shows theweight gain of the polymer against time of interaction between thepolymer and the sea water. The results show that the polymer absorbsmore than ten (10) times its own weight of sea water in two hours.

Example 3

FIG. 3 shows the effect of a thirty (30) degree rise in temperature onsea water absorption. The higher temperature does not have a negativeeffect on water absorption capacity of the polymer.

Example 4

One gram of polymer was dispersed in a 100 mL beaker of a mineral oil(EDC 95/11, Total). The mixture was gently stirred for two hours toallow the polymer surfaces to become fully oil-wet. A 50 mL volume ofsea water was then added to the oil phase as the stirring continued. Thepolymer granules were weighed at intervals. FIG. 4 charts the weight ofthe absorbed sea water against time. Comparison with FIG. 2 shows thatthe presence of the oil does not inhibit absorption of sea water by thepolymer.

Example 5

Two and a half (2.5) grams of an invert emulsifier (VERSACLEAN FL®, M-ISWACO) was dissolved in 100 mL of mineral oil. One gram of polymer wasadded to the oil. Stirring continued for two hours to allow the polymersurfaces to become fully oil-wet. A 50 mL volume of sea water was thenadded to the oil phase with gentle stirring. The polymer granules wereweighed at intervals. FIG. 5 shows the weight of the absorbed sea wateragainst time. Comparison with FIGS. 2-5 shows that the presence of theoil and emulsifier does not inhibit absorption of sea water by thepolymer. It should be noted that high-shear mixing, which is requiredfor forming a stable emulsion, was not applied in this test. (i.e. themixture was stirred gently at all times)

Example 6

Two and a half (2.5) grams of emulsifier was dissolved in 100 mL ofmineral oil. One hundred eighteen (118) grams of barite was added to theoil and the mixture was sheared for thirty (30) minutes. One gram of thepolymer was added to the oil-barite suspension and stirring continuedfor two hours. A 50 mL volume of sea water was then added to thesuspension with gentle stirring. The polymer granules were removed atintervals by sieving and shaking to ensure that most of the oilysuspension was removed from the swollen particles before weighing. FIG.6 shows the weight of absorbed sea water against time. Comparison withFIGS. 4 and 5 shows that the presence of barite particles reduces waterabsorption by the polymer. This may be due to coverage of polymergranules with fine particles of barite. Nevertheless, the polymer iscapable of absorbing seven times its own weight of sea water in three(3) hours.

The following examples show the water absorption capability of thepolymer when the water is present in an emulsified state, which is thecase with invert emulsion fluids.

Example 7

Two and a half (2.5) grams of emulsifier was dissolved in 100 mL ofmineral oil. A 30.7 mL volume of fresh water was added to the oil andthe mixture was subjected to high shear for thirty (30) minutes using aHamilton Beach mixer. One gram of polymer was then added to the emulsionand the mixture was stirred gently. The polymer granules were removed atinterval and weighed. FIG. 7 shows the weight of absorbed fresh wateragainst time. The polymer readily absorbs fresh water, up to fourteen(14) times its own weight, even when the water is in an emulsifiedstate.

Example 8

A 22% (w/w) calcium chloride brine was made by dissolving 10.9 grams ofcalcium chloride (oilfield grade, 83.5% purity) in 30.7 mL of freshwater (equivalent to a water phase salinity of 173,887 mg/L of chlorideions, a common oilfield unit). Two and a half (2.5) grams of emulsifierwas dissolved in 100 mL of mineral oil The 30.7 mL volume of 22% (w/w)calcium chloride brine was added to the oil and the mixture wassubjected to high shear for thirty (30) minutes using a Hamilton Beachmixer. One gram of polymer was then added to the emulsion and themixture was stirred gently. The polymer granules were removed atinterval and weighed. FIG. 8 shows the weight of absorbed brine againsttime. This is the worst case scenario for water absorption as bothsalinity and emulsification reduce absorption of water by the polymer.Nevertheless, the polymer is capable of absorbing more than three timesits own weight of brine from a concentrated emulsified brine phase.

Example 9

A test was conducted to determine whether it was water or brine that wasabsorbed by the polymer. Three hundred (300) grams of a 22% (w/w)solution of calcium chloride was prepared as described in Example 8. Thewater activity of this solution was measured by a Novasina WaterActivity Meter (Model ms1-aw) to be 0.796 at 22.5° C. Fifteen (15) gramsof the polymer was added to the brine and mixed by gentle stirring.After eight hours, the polymer granules were removed by sieving, andsubsequently weighed. A weight gain of 77.9 gram was registered. Thewater activity of the remaining brine was measured to be more or lessunchanged, 0.790 at 24.0° C.

FIG. 9 shows the percent concentration (w/w) against water activity. Ifthe weight gain of the polymer was due to absorption of pure water,rather than brine solution, then the salt concentration of the remainingbrine would have increased to 29.9%, equivalent to a water activity ofabout 0.64, as shown in FIG. 9. As mentioned above, the measured wateractivity of the remaining brine was 0.79. Therefore, it is concludedthat the polymer absorbs the salt solution rather than pure water.

While the claimed subject matter has been described with respect to alimited number of embodiments, those skilled in the art, having benefitof this disclosure, will appreciate that other embodiments can bedevised which do not depart from the scope of the claimed subject matteras disclosed herein. Accordingly, the scope of the claimed subjectmatter should be limited only by the attached claims.

1. A method for removing aqueous fluid from a wellbore fluid,comprising: contacting the wellbore fluid with a water absorbingpolymer, the wellbore fluid comprising: an invert emulsion; interactingthe water absorbing polymer with the wellbore fluid so that the waterabsorbing polymer absorbs at least a portion of the aqueous fluid fromthe wellbore fluid; and separating the water absorbing polymercontaining the absorbed aqueous fluid from the wellbore fluid.
 2. Themethod of claim 1, wherein the invert emulsion is comprised of anoleaginous continuous phase and an aqueous discontinuous phase.
 3. Themethod of claim 2, wherein the oleaginous continuous phase is selectedfrom at least one of mineral oil, synthetic oil, diesel, crude oil, andmixtures thereof.
 4. The method of claim 2, wherein the aqueousdiscontinuous phase is selected from at least one of fresh water, seawater, brine, mixture of water and water soluble organic compounds, andmixtures thereof.
 5. The method of claim 1, wherein the water absorbingpolymer is a water absorbing crystalline polymer capable of absorbing atleast ten times its own weight in fresh water.
 6. The method of claim 5,wherein the water absorbing polymer is selected from at least one ofacrylamide based polymers and copolymers, starch derivatives, andcombinations thereof.
 7. The method of claim 1, wherein the sufficientperiod of time is one to three hours.
 8. The method of claim 1, whereinthe separating step further comprises passing the wellbore fluid over ashaker screen.
 9. A method for removing non-emulsified aqueous contentfrom a wellbore fluid in situ, comprising: determining a design limit ofthe oil-to-water ratio for the wellbore fluid; feeding the wellborefluid to the borehole, the wellbore fluid comprising: an invertemulsion; monitoring the oil-to-water ratio of the wellbore fluid;adding a water absorbing polymer when the oil/water ratio decreasesbelow the design limit; allowing the water absorbing polymer to interactwith the wellbore fluid so that the water absorbing polymer absorbssufficient aqueous content to return the oil/water ratio above thedesign limit; and separating the water absorbing polymer containing theabsorbed water from the wellbore fluid.
 10. The method of claim 9, wherethe oil-to-water ratio of the wellbore fluid is intermittentlymonitored.
 11. The method of claim 9, where the oil-to-water ratio ofthe wellbore fluid is continually monitored.
 12. The method of claim 9,where the water absorbing polymer is added directly to an active borehole pit.
 13. The method of claim 9, where the water absorbing polymeris added through a flow line carrying the wellbore fluid.
 14. The methodof claim 9, where the water absorbing polymer is selected from at leastone of acrylamide based polymers and copolymers, starch derivatives, andcombinations thereof.
 15. The method of claim 14, where the waterabsorbing polymer is 0.3-1.0 millimeter polymer polymer granules. 16.The method of claim 9, where the separating step further comprisespassing the wellbore fluid over a shaker screen.
 17. A method forremoving emulsified aqueous content from an existing invert emulsionwellbore fluid, where the existing invert emulsion wellbore fluidcomprises an existing oil-to-water ratio, comprising: determining adesired oil-to-water ratio for the existing invert emulsion wellborefluid; adding a sufficient amount of water absorbing polymer to theexisting wellbore fluid to adjust the existing oil-to-water ratio to thedesired oil-to-water ratio; allowing the water absorbing polymer tointeract with the existing wellbore fluid for a sufficient period oftime so that the water absorbing polymer absorbs sufficient aqueouscontent to adjust the existing wellbore fluid to the desiredoil-to-water ratio, thereby yielding an adjusted wellbore fluid; andseparating the water absorbing polymer containing the absorbed aqueouscontent from the adjusted wellbore fluid.
 18. The method of claim 17,where the water absorbing polymer is selected from at least one ofacrylamide based polymers and copolymers, starch derivatives, andcombinations thereof.
 19. The method of claim 17, where the waterabsorbing polymer is 0.3-1.0 millimeter polymer granules.
 20. The methodof claim 17, where the separating step further comprises passing thewellbore fluid over a shaker screen.